Low friction loss method for fracturing a subterranean geothermal earth formation

ABSTRACT

A low friction loss process for fracturing subterranean formations where the fracturing fluid includes a metal-plated, polymer-coated propping agent. Useful polymers include low-density polyethylene, polypropylene, etc.

This is a division of applicaton Ser. No. 570,157, filed Apr. 21, 1975.

BACKGROUND OF THE INVENTION

Field of the Invention

This invention relates to a method of fracturing a geothermal formation.More particularly, this invention relates to a fracturing method inwhich the fracturing fluid includes a metal-plated propping agent coatedwith a thermoplastic polymer.

Prior Art

One of the major sources of energy in the world is the natural heat ofthe earth. A number of attempts have been made to recover heat from thegeothermal formations or hot formations of the earth; however, only anextremely small quantity of energy compared to the total amount consumedis derived from this source at the present time. In California aloneover 1 million acres of land are classified as being in geothermalresource areas. Steam derived from geothermal sources is being employedin the United States, Italy, Mexico, Russia, New Zealand and Japan todrive turbines for electrical power generation. In Iceland, hot waterderived from hot artesian wells or springs is transmitted through pipesand utilized in heating buildings and greenhouses.

The desirability of utilizing heat derived from a geothermal source isapparent since the fossil fuel sources, i.e., coal, oil, peat, etc. arelimited and can be exhausted within a few decades at the present rate ofproduction.

All of the installatins in operation today employing energy derived fromgeothermal sources operate with hot water and/or steam derived fromgeothermal formations into which underground water flows and becomesheated. One of the most successful geothermal installations is thatoperated in Northern California to produce electricity. In thisgeothermal reservoir subterranean water contacting the hot reservoirrock structure is flashed into steam forming a very large steamreservoir at temperatures of the order to 500°-550° F. or more whileshut-in pressure of the wells below 2000 feet is 450-480 psig.

The use of steam and/or hot water produced in geothermal reservoirssuffers from several major disadvantages. Frequently, large volumes ofnoxious gases such as hydrogen, sulfide, carbon dioxide, hydrocarbons,ammonia, etc. are produced with the steam or water and these gases mustbe removed and disposed of in a manner which will not pollute theenvironment. The mineral content of the steam and/or water recoveredfrom any geothermal wells is so high that the steam recovered may be socorrosive as to preclude its use in turbines, etc. In most instanceswhere water is recovered with the steam, the salinity is usually of suchmagnitude that the cool brine can be discharged to surrounding streamsor lakes only after being treated to reduce the salinity to anacceptable value. Furthermore, many plants which utilize steam fromgeothermal reservoirs for turbine power generation discharge acondensate from the condensers which is so high in boron that the toxiceffluent must be sent to an appropriate treatment plant or returned tothe underground reservoir through a disposal well.

There is a definite need in the art therefore for a process in whichenergy in the form of heat can be recovered from a geothermal formationwithout the removal from the formation of substantial quantities of thehighly corrosive brines associated with these formations. Among theadvantages of such a process are: (1) subsidence of the producing areawould be prevented and (2) the heat transfer medium, i.e., the brine,would be retained in the formation.

There is a definite need in the art for a low friction loss method offracturing geothermal formations in which the propping agents includedwith the fluid employed in the fracturing process also will serve toimprove the rate of heat transfer between the hot formation and thefluid therein

BRIEF SUMMARY OF THE INVENTION

In its broadest sense this invention is concerned with a low frictionloss method for fracturing a subterranean earth formation penetrated bya well in which the fracturing fluid is injected through the well andinto the earth formation at a high velocity to cause fracturing of theformation. In this invention the fracturing fluid injected into theformation via the said well contains a metal-plated, propping agentcoated with a thermoplastic polymer.

A wide variety of organic fluids having a low solubility in water areuseful in the method of this invention. Suitable fluids include, forexample, normally liquid hydrocarbons having from 4 to 10 inclusivecarbon atoms such as propane, butane, pentane, heptane, octane, decane,etc., and isomers and mixtures thereof. Other suitable hydrocarbonsinclude selected hydrocarbon cuts such as middle distillates, naphthas,etc. The preferred hydrocarbons are those which have low mutualsolubility with water. Any hydrocarbon fluid having suitable physicaland thermodynamic properties which does not react chemically with thegeothermal formation to any excessive degree may be employed in themethod of this invention.

The heated organic fluid withdrawn from the production well in theprocess of this invention may be in vapor form, a mixture of vapor andliquid or liquid alone depending on the temperature of the fluid as itleaves the hot, geothermal formation and enters the borehole of theproduction well and on the pressure maintained in the withdrawal system.Preferably, in the process of this invention the organic fluid withdrawnfrom the production well is maintained in the liquid state through theuse of appropriate pressure control valves.

In another aspect, this invention relates to a process for convertingthe heat energy of the heated organic fluid recovered from theproduction well in liquid phase which comprises:

(a) separating brine from the said organic fluid in liquid phase,

(b) reducing the pressure in the said liquid phase thereby convertingthe organic fluid to a vapor phase,

(c) expanding the organic fluid in vapor phase in a power extracting gasexpansion device, and

(d) condensing the organic fluid in vapor phase after expansion therebyforming an organic fluid liquid phase and a separate water liquid phasederived from water dissolved in the organic fluid recovered from theproduction well.

After step (d) the organic fluid in liquid phase is separated from thewater phase and recycled to the geothermal formation. The powerextracting gas expansion device can be, for example, a turbine which canbe direct connected to an electrical generator, if desired.

In the process of this invention the heated organic fluid recoverd fromthe production well can be passed through a boiler or heat exchangerwhere it is employed to heat and/or vaporize a second fluid or workingfluid which can be, for example, water, steam, isobutane, pentane,isopentane, ethylene glycol, kerosene, crude oil, etc., or,alternatively, the heated fluid recovered from the production well maybe utilized directly for heating purposes or as a reactor input stream,etc., and where the recovered heated fluid is a vapor it can, ifdesired, be employed directly to drive a turbine, etc.

The working fluid leaving the heat exchanger may be employed in avariety of ways as a heating medium for such process requirements assteam raising, evaporation, reactor heating, preheating of reactor inputstreams, etc. The heated working fluid may also be employed inagricultural production to heat fields, greenhouses, etc., thuspermitting a number of crops to be grown in areas with short growingseasons by preventing frost damage and freezing of the ground.

As the organic liquid is forced through the geothermal formation, itcontacts by the hot brine in the geothermal formation as well as the hotgeothermal formation itself and is heated to formation temperature whichmay be from about 250° to about 900° F. and preferably, from about 400°to about 900° F. In this process the handling of corrosive brine orsteam contaminated with brine is minimized by an in situ transfer ofheat to the organic fluid. The brine components are insoluble in theorganic fluid and the hot organic fluid recovered via the productionwell is substantially free of brine components. Since a small amount ofbrine may be carried out of the formation with the hot organic fluid, itis preferable to send the hot organic fluid recovered via the productionwell to a separator located on the surface for removal of the brineprior to utilization of the fluid in turbine operation.

After the organic fluid has been expanded to form a gaseous phase and,for example, employed for driving a turbine, it is sent to heatexchanging device where it is condensed. The heated fluid leaving theheat exchanger also may be utilized in a variety of heating operationssuch as heating crude oil serving as refinery feedstock. During thepassage of the organic fluid through the geothermal formation a smallamount of water derived from the brine is dissolved in the organic fluidand this water is preferably removed from the organic fluid after thefluid has been condensed in the heat exchanging device. This isaccomplished by sending the condensed organic fluid to a gravityseparator or decanter. From the bottom of this separator desalinatedwater is removed while condensed organic fluid is withdrawn from the topand recycled to the geothermal formation via the injection well. Thedesalinated water may likewise be returned to formation via theinjection well or it may be utilized as boiler feed water, etc.

The process of this invention offers a number of distinct advantagesover processes previously proposed for utilizing geothermal energy suchas the following:

1. Heat is transferred to a non-corrosive working fluid, a hydrocarbon,which is separated from the brine in the formation and circulted to thesurface to recover the heat. High alloy, stainless steels are not neededeffecting a large savings in capital investment.

2. The low corrosion characteristic of the hydrocarbon fluid greatlyreduces the maintenance compared to systems utilizing brines.

3. Electric power is recovered from the heated hydrocarbon working fluidwithout producing by-products such as brine streams which would eitherhave to be returned to the formation or discharged to the environment.

4. A near pollution free operation is obtained.

BRIEF DESCRIPTION OF THE DRAWING

The FIGURE shown is a schematic drawing illustrating recovery of heatfrom a geothermal formation where an organic fluid in a closed circuitis passed through a geothermal formation, withdrawn from a productionwell and heat derived from the fluid is utilized in preparing electricalpower.

DETAILED DESCRIPTION OF THE INVENTION

As previously pointed out, this invention is concerned with a method offracturing geothermal reservoir formations which contain a substantialamount of brine. In this specification a geothermal reservoir is definedas a reservoir or system where rock formations are heated by the normalgeothermal gradient and where there is fluid generally in the form ofbrine for heat transfer. Wells, i.e., the injection and productionwells, employed can be drilled utilizing the same equipment andtechniques employed in drilling wells for the recovery of petroleumhydrocarbons. These geothermal reservoir formations generally will besituated from about 1000 to about 30,000 feet or more below the surface.

A number of injection wells and production wells may be utilizedsimultaneously in recovery heat from the geothermal reservoir. Suchwells may be arranged in any convenient pattern such as the invertedfive-spot pattern, the inverted seven-spot pattern, or in any othersuitable pattern. In the inverted five-spot pattern four productionwells are situated at corners of a square while a single input well islocated at the center of the square. The distance between a productionwell and an injection well can be varied widely depending upon thetemperature of the formation, the particulr organic fluid beingcirculated through the hot formation, the circulation rate of the fluidand the increase in temperature desired in the injected organic fluid,etc. Generally, the distance between any particular injection well andproduction well will be from about 10 to about 400 feet or more.

If the fluid conductivity of the geothermal reservoir formationpenetrated by the injection or production well is found to be low, as isfrequently the case, or if it is desired to further increase the fluidconductivity, the formation in the injection well, production well, orboth may be subjected to remedial action in order to increase thepermeability of the formation. One common method for increasng thepermeability of the formation which has been practiced for a number ofyears in the art is known as hydraulic fracturing. In this methodartificial fractures or channels of high fluid conductivity within theformation can be formed.

The geothermal reservoir formation in the injection well or theproduction well can be conveniently fractured by methods well known inthe art by pumping a fluid down the well bore and into contact with theformation at a rate higher than that at which the fluid can flow intoand through the formation. On continued injection of the fluid, thepressure within the well bore increases to a pressure at which theformation breaks down to create one or more fractures or fissuresextending outwardly from the well bore into the formation. The hydraulicfracturing fluid is injected into the formation at a sufficient pressureand flow rate to generate the required fracture and to displace thefluid into the fracture under laminar flow conditions. Any of thecommonly employed hydraulic fracturing fluids such as water, hydrocarbonoils or oil-in-water emulsions, etc., together with viscosity thickenersand other additives may be used in fracturing the geothermal reservoirformations.

After the pressure on the fracturing fluid has been reduced, thefractures will tend to close somewhat because of the unbalancedcompressive forces in the formation. If desired, propping agents may beincluded in the hydraulic fracturing fluids previously described toprevent closure of the fractures, or they may be introduced into thefractured formation as a component of an aqueous fluid, a hydrocarbonfluid, etc., after the initial fracturing operation has been completed.Useful propping agents include sand grains, metal shot including steelshot, plastic particles, glass beads, ceramic particles, etc.

The quantity of the fracturing fluid required per well will vary widelydepending on the physical properties of the formation, the thickness.For example, in a typical fracturing operation of a well employed in theprocess of this invention a mixture comprising about 10,000 to about60,000 pounds of sand in 2,000 barrels or more of kerosene or water isused.

Hydraulic fracturing methods suitable for use in fracturing wellscompleted in geothermal reservoir formations are more fully described inU.S. Pat. Nos. 3,638,727, 3,010,513, 3,366,176, 3,376,929, 3,497,008,2,944,018, 2,962,095, 3,149,673, 3,175,615, 3,317,967, etc.

One of the problems associated with the recovery of energy in the formof heat from geothermal formations is the low rate of heat transfer fromthe formation to the fluid being heated. It has been found that thisrate of heat transfer can be substantially improved if during thefracturing step propping agents having metallic surfaces such as metalshot including steel shot or sand grains which have been metal platedeither electrolessly or by electroplating are employed. Nickel or cobaltare the preferred metals for forming such coatings since they are highlyresistant to the corrosive brines present in the formation.

In preparing electrolessly plated sand grains in the first step sandgrains having a size of 8 to 40 Tyler Mesh (i.e., 0.016 to 0.093 inches)are boiled in hydrochloric acid (5 weight percent) for about 1 hour,removed from the acid bath and thoroughly washed with clean water. Next,the grains are immersed in an aqueous solution containing an activatingagent, such as colloidal palladium formed by the reaction of stannouschloride and palladium chloride, for the purpose of activating thesurface of the particles to be plated. The formula composition of asuitable activating solution is as follows:

PdCl₂ -- 1.1 g

Water -- 560 ml

Hcl (cmc) -- 285 ml

Sncl₂ -- 50 g

Compositions of this type are more completely described in U.S. Pat. No.3,011,921 which is incorporated herein in its entirety. Finally, thethus-activated sand grains are electrolessly plated by immersion withvigorous mixing in an aqueous plating solution containing a metalplating compound and a reducing agent. The composition of a suitableelectroless nickel plating solution is as follows:

N₁ cl₂ .sup.. 6H₂ O -- 35 g

NaH₂ PO₂ .sup.. H₂ O -- 12 g

Nh₄ cl -- 60 g

Trisodium Citrate .sup.. 5.5H₂ O -- 110 g

Water to make -- 1 liter

Operate at 195° F., Adjust pH to 8-10 with NH₄ OH.)

if it is desired to electrolessly plate the sand grains with cobalt, thefollowing composition can be utilized:

CoCl₂ .sup.. 6HO -- 30 g

NaH₂ PC₂ H₂ O -- 22 g

Rochelle salts (NaKC₄ H₄ O₆ .sup. 4H₂ O) -- 200 g

Nh₄ cl -- g

Water to make -- 1 liter

(Operate at 190° F. at pH of 8.5 to 10, Adjust pH with NH₄ OH.)

the plated sand grains are then removed from the plating solution,washed with clean water and dried in a hot air drier. Metal shot such assteel shot may be electrolessly plated with a coating of nickel orcobalt metal in the same manner as disclosed above.

In accomplishing the first step of the electroless plating operation, asactivater solutions one may use acidic solutions of palladium chlorideand/or stannous chloride, or the corresponding bromide, nitrate orsulfate solutions. The activator solution should also contain a reducingagent, such as hydrazine, sodium hypophospite, a low aldehyde, e.g.,formaldehyde, etc.

Preferably, the activator liquids are acid aqueous solutions acidifiedwith acetic, formic or hydrochloric acid, etc. Other activator fluidswhich can be employed are aqueous solutions containing gold, ruthenium,rhodium or platinum, etc., together with a reducing agent such ashydrazine, and with or without a protective colloid such as gum arabic,tragacanth gum, gelatin, etc. The function of the reducing agent is toreduce the metal salt in the activator solution to the free metal whichmay be in colloidal form. Other activator liquids commonly used forelectroless metal plating of non-metallic objects may similarly be used.

The metal-containing plating solution can be acidic, having a pH of from2 to 6, and a pH range of from 4 to 6 is especially preferable. Alkalinemetal plating solutions may also be used, where desirable.

Metal plating compositions suitable for use in the preparation of thesteel or sand plated particles include, for example, nickel, or cobaltchlorides and/or the corresponding sulfates. Reducing compositionsuseful in such electroless plating compositions include reagents such ashypophosphorous acid, hypophosphites, e.g., sodium hypophospite, oralkaline solutions of formate, molybdenate and/or hydroxy carboxylates.The metal-containing compounds and the reducing agents may be present inconcentrations ranging from about 1 to about 40 percent by weight each.A variety of suitable electroless metal plating solutions have beendescribed in U.S. Pat. Nos. 3,393,737, 3,500,926, 3,500,927, 3,586,524,3,438,411, etc., which are incorporated herein by reference in theirentirety. The initially applied electroless coating can be electroplatedover with nickel or cobalt until the desired metal thickness isobtained.

In order to protect the thin, plated metal film on the steel shot or onthe sand grains as they are carried into the formation during thefracturing operation, the plated particles may be coated with forexample, a thin film of low-density polyethylene (density about 0.91 toabout 0.94 g/cc or high-density polyethylene (density about 0.95 toabout 0.97 g/cc), or any other thermoplastic having a melting pointbelow about 300° F. The plastic film thickness needed can range from0.001 to 0.005 inch although a thickness more or less than set out inthis range can be utilized, if desired.

In preparing polymer-coated, plated sand grains a solution of from about0.5 to about 1.5 percent or more by weight of the thermoplastic polymerprepared by dissolving pellets of the polymer in 1,1,2-trichloroethane,1,1,2,2-tetrachloroethane, carbon tetrachloride, or chlorobenzene, etc.at temperatures about 100° C. Plated sand grains having a Tyler meshsize of about 8 to 40 are then added with stirring to the thus-preparedpolymer solution after which the polymer-coated grains are separatedfrom the solution and dried. In a specific illustration of thepreparation of such polymer-coated, plated sand grains a solution of 0.7weight percent low density polyethylene is formed by adding polyethylenepellets with stirring to 1,000 gallons of chlorobenzene at 105° C. Tothis polymer solution 2,000 lbs. of clean nickel-plated sand having aTyler mesh size of 8 to 20 are added with vigorous mixing to thechlorobenzene solution maintained at about 105° C. Mixing is continuedfor about 20 minutes after which the coated, plated sand grains arerecovered by filtration and then dried by tumblind in hot air at atemperature of about 130° F.

An added advantage in using the polymer-coated propping agents such asthe plated sand grains or steel shot in the fracturing process utilizedin this invention is that a substantial reduction in friction loss isachieved at the pressures employed which may be as high as 3,000 to10,000 psi or more (measured at the surface). Polymer-coated sand grainswhich have not been metal plated prepared in the same manner asdescribed above may also be used in the fracturing operations of thisinvention. After the polymer-coated propping agents have been depositedin the formation from an aqueous or hydrocarbon fracturing fluid, thecoating is gradually removed by the hydrocarbon being circulated throughthe formation since the temperature in the formation is generallysubstantially above the melting point of the polymer and the solubilityof these polymers in the hydrocarbons at these temperatures is in mostcases appreciable. In this manner the polymer coating is removed fromthe plated, propping agents and the clean, metallic, high heat transfersurfaces of these propping agents are exposed.

Additional reduction in friction losses during the fracturing operationcan be achieved where aqueous fracturing fluids of the type previouslydescribed containing any of the above-described propping agents areemployed by adding 0.005 to about 3 weight percent of a polyacrylamidepolymer or a partially hydrolyzed polyacrylamide polymers in which 20 to40 percent of the available amide groups are hydrolyzed with forexample, sodium hydroxide. Only high molecular weight polyacrylamideshaving a molecular weight such that a 0.5 weight percent solution of thepolymer in a 4 weight percent aqueous sodium chloride solution has anOstwald viscosity in the range of 8 to 60 centipoises at 25° C. areuseful. These polymers are more completely described in U.S. Pat. No.3,254,719.

In the low friction loss method of fracturing a subterranean formationpenetrated by a well a fracturing fluid is injected through the wellinto the earth formation at a high velocity to cause fracturing of theformation, which comprises adding to the fracturing fluid selected fromthe group consisting of aqueous fluids and hydrocarbon fluids, apropping agent selected from the group consisting of steel shot or sandgrains electrolessly plated with nickel or cobalt and coated on theplated metal surfaces thereof with a thermoplastic polymer, preferablyhaving a melting point less than 300° F., and, optimally a smallquantity of a polyacrylamide or hydrolyzed polyacrylamide friction lossreducing agent and injecting the resulting mixture into the formationvia the said well.

In the preferred method of practicing the fracturing operation, a slugof about 5,000 to about 150,000 gallons of the fracturing fluid whichcan be water, brine, oil, kerosene, middle distillate, etc. containingabout 0.2 to about 5.5 pounds per gallon of the propping agent, isinjected down the well and into contact with the formation under apressure and volume flow rate sufficient to form a fracture in theformation extending outwardly from the well bore which is propped openby the propping agent.

In the FIGURE there are shown injection well 2 and production well 4which are 220 feet apart and which extend from the surface of earth 6down through the upper formation 8 into a geothermal formation 10 havingassociated with it corrosive brine and steam and exhibiting atemperature of about 600° F. Well 2 is cased with steel pipe casing 12and the bottom of the well is plugged back with a suitable cement layeror plug 14. The 20 foot interval (8,210 -8,230 feet) above plug 14 ofthe casing in well 2 is perforated in a conventional manner to form afluid passageway between the well bore and formation 10 via perforations22. Steel tubing 16 is installed in the well bore to a point about 20feet above plug 14 where it passes through packer 20.

Well 4 is cased with steel pipe casing 17 and the bottom of this well isplugged back with a suitable cement layer 18. Both wells 2 and 4 arecompleted at the same depth in the geothermal formation. The 20 footinterval above plug 18 of casing 16 is perforated in conventional mannerto form a fluid passageway between the well bore and the formation 10via perforations 24. Steel tubing 26a is installed in the well bore ofwell 4 to a point about 20 feet above plug 18 where it passes throughpacker 26.

Prior to injection of the organic fluid into the geothermal formationhydraulic fracturing of the formation in both the injection well and theproduction well is carried out.

Injection well 2 is prepared for hydraulic fracturing in the usualmanner and fracturing is accomplished by injecting via steel pipe casing12 and into the formation through casing perforations 22, 25,000 gallonsof fresh water gelled with guar gum and containing 1.3 pounds per gallonof nickel-plated sand grains with an outer coating of low-densitypolyethylene at the rate of about 30 barrels per minute at a pressure of4,000 psig (max.). Production well 4 is hydraulically fractured in thesame manner employing the same type of fracturing fluid.

By means of high pressure pump 30 liquid pentane at a temperature ofabout 150° F. is passed via line 32 into tubing 16 of well 2. Makeup,liquid hydrocarbon (i.e., pentane) is introduced into line 32 by meansof high pressure pump 32a and line 32b. The liquid hydrocarbon is thentransmitted downwardly through tubing 16 and forced into formation 10through perforations 22. As the liquid hydrocarbon is forced through theformation 10, it contacts the hot corrosive brine and steam containedtherein and is heated and enters the wellbore of well 4 throughperforations 24 at a temperature of about 590° F. From the wellbore ofwell 4 it is withdrawn via tubing 26a and conducted by line 36 to pump38 and then passed via line 40 into brine separator 42 where the verysmall amount of brine brought up from the geothermal formation in thehot hydrocarbon fluid is permitted to settle out. The hot hydrocarbonfluid is withdrawn from the top of separator 42 and is passed by meansof line 44 into coalescer 46 to remove the last traces of brine.Optionally, one may introduce via line 60a, high pressure pump 60b andline 60c a small amount of hot water to aid in the separation of thefinal traces of brine in coalescer 46. Brine from the bottom of brineseparator 42 is passed by line 48 and 50 to the suction side of pump 52and brine from the bottom of coalescer 46 also is sent via line 54 andline 50 to the suction side of pump 52. From the discharge side of pump52 the removed brine is transmitted via line 56 to a disposal unit forrecovery of chemicals contained in the brine or, optionally, the brinecan be returned to the formation via line 58. From the coalescer 46 thehot liquid hydrocarbon is passed via line 64 to low pressure turbine 66where it is expanded into gaseous phase. Low pressure turbine 66 whichis directly connected to a suitable electrical generator 68. Leavingturbine 66 via line 70 the exhaust vapors are conducted to a shell andtube condenser 72 where they are condensed to form a pentane phase and aseparate water phase derived from the small amount of water whichdissolves in the pentane as it is passed through the geothermalformation. Condenser 72 is cooled by water which enters via line 74 at atemperature of about 100° F. and leaves the condenser at about 130° F.via line 76. Alternatively, 72 may be a secondary heat recovery device.Liquid pentane and water are withdrawn from condenser 72 via line 78 andpassed to water separator 80 which serves to remove the water phase.From the top of separator 80 the liquid pentane phase is sent to suctionside of pump 30 via line 82. Desalinated water which separates from theliquid hydrocarbon stream is removed from the bottom of separator 80 vialine 84 for utilization as boiler feed water, etc. or it may be returnedto the formation along with the liquid hydrocarbon, if desired.

A single well method of heating a fluid in a brine-containing geothermalreservoir formation penetrated by a well having two separated fluid flowpassages terminating at different levels in the geothermal formation mayalso be practiced. Such a process comprises

(a) pumping an organic fluid having a low solubility in water down thedeeper of the fluid flow passages of the said well and into theformation thereby heating the said organic fluid,

(b) recovering the heated organic fluid substantially free of brinethrough the shallower flow passage in the said well, and wherein thetemperature of the said geothermal reservoir formation is substantiallyabove the temperature of the fluid introduced into the formation in step(a).

Preferably, at least a portion of that section of the geothermalformation between the terminal levels of the two flow passages of thewell is hydraulically fractured in the manner set out above. Any of theorganic fluids mentioned above can be utilized in the single well methodsuch as the normally liquid hydrocarbons having from 4 to 10 inclusivecarbon atoms.

In this method of operating a single well penetrating the geothermalformation and having a casing set about 20 to about 50 feet or moreabove the bottom of the well is utilized. Tubing is run to a point belowthe casing but from about 2 to about 10 feet or more above the wellbottom and preferably the well bore section between the bottom of thecasing and the bottom of the well is fractured in the same manner aspreviously described to open up the formation. The recycling hydrocarbonwhich is introduced into the hot geothermal formation via the deeperextending tubing circulates upwardly in the formation and the heatedfluid is withdrawn via the shallower flow passage, i.e. the annulusbetween the tubing and the casing. Utilization of the heated hydrocarbonfluid at the surface is conducted in the same manner as described abovein connection with the two well system.

What is claimed is:
 1. A low friction loss method for fracturig asubterranean hot geothermal earth formation penetrated by a well,wherein a fracturing fluid is injected through the well and into theearth formation at a high velocity to cause fracturing of the formationwhereby the rate of heat transfer between the formation and theformation fluid is improved, which comprises injecting into theformation a fracturing fluid to which there has been added anelectrolessly metal-plated, metal shot propping agent coated with athermoplastic polymer, and injecting the resulting mixture into theformation via the said well.
 2. The method of claim 1 wherein the saidfracturing fluid is selected from the group consisting of aqueous fluidsand hydrocarbon fluids.
 3. The method of claim 1 wherein the saidfracturing fluid is water.
 4. The method of claim 1 wherein the saidfracturing fluid is crude oil.
 5. The method of claim 1 wherein the saidfracturing fluid is kerosene.
 6. The method of claim 1 wherein the saidthermoplastic polymer is selected from the group consisting oflow-density polyethylene, high-density polyethylene, polypropylene andpolycarbonates.
 7. The method of claim 1 wherein the said resultingmixture contains from about 0.2 to about 5.5 pounds per gallon of thesaid propping agent.
 8. The method of claim 1 wherein the saidfracturing mixture comprises a fracturing fluid selected from the groupconsisting of aqueous fluids and hydrocarbon fluids, the saidelectrolessly plated propping agent is selected from the groupconsisting of nickel-plated steel shot and cobalt-plated steel shot andthe said thermoplastic is selected from the group consisting oflow-density polyethylene, high-density polyethylene, polypropylene andpolycarbonates.
 9. The method of claim 1 wherein the said fracturingmixture comprises water containing about 2.1 pounds per gallon oflow-density, polyethylene-coated, nickel-plated, steel shot.
 10. Themethod of claim 1 wherein the said metal-plated propping agent iselectrolessly plated steel shot.